1. Field of the Invention
The present invention relates to a system and method for transmitting information from a downhole location to surface location. More particularly, the present invention relates to a system and method for communicating the inclination angle at the bottom of a wellbore to a surface location in a generally real-time fashion without the need for wirelines or remote transmission. The present invention also relates to the association of pressure transducer measurements to monitor pressure changes as a method of transmission of information.
2. Description of Related Art Including Information Disclosed Under 37 CFR 1.97 and 37 CFR 1.98.
In underground drilling, such as gas, oil or geothermal drilling, a bore is drilled through a formation deep in the earth. Such bores are formed by connecting a drill bit to sections of long pipe, referred to as a “drill pipe,” so as to form an assembly commonly referred to as a “drill string” that extends from the surface to the bottom of the borehole. The drill bit is rotated so that it advances into the earth, thereby forming the bore. In rotary drilling, the drill bit is rotated by rotating the drill string at the surface. In directional drilling, the drill bit is rotated by a downhole mud motor coupled to the drill bit; the remainder of the drill string is not rotated during drilling. In a steerable drill string, the mud motor is bent at a slight angle to the centerline of the drill bit so as to create a side force that directs the path of the drill bit away from a straight line. In any event, in order to lubricate the drill bit and flush cuttings from its path pumps on the surface pump fluid at a high pressure, referred to as “drilling mud”, through an internal passage in the drill string and out through the drill bit. The drilling mud then flows to the surface through the annular passage formed between the drill string and the cut formation borehole.
Depending on the drilling operation, the pressure of the drilling mud flowing through the drill string will typically be between 500 psi and 5000 psi. Some of this pressure is lost at the drill bit so that the pressure of the drilling mud flowing outside the drill string is less than that flowing inside the drill string. In addition, the components of the drill string are also subjected to wear and abrasion from drilling mud, as well as the vibration of the drill string.
The distal end of a drill string is the bottom hole assembly (BHA), which includes the drill bit, the drilling sub and drill collars. In “measurement while drilling” (MWD) applications, sensing modules in the BHA provide information concerning the direction of the drilling. This information can be used, for example, to control the direction in which the drill bit advances in a steerable drill string. Such sensors may include a magnetometer to sense azimuth and accelerometers to sense inclination and tool face direction.
Historically, information concerning the conditions in the well, such as information about the formation being drilled through, was obtained by stopping drilling, removing the drill string, and lowering sensors into the bore using a wireline cable, which were then retrieved after the measurements had been taken. This approach was known as wireline logging. More recently, sensing modules have been incorporated into the BHA to provide the drill operator with essentially real-time information concerning one or more aspects of the drilling operation as the drilling progresses. In “logging while drilling” (LWD) applications, the drilling aspects about which information is supplied comprise characteristics of the formation being drilled through. For example, resistivity sensors may be used to transmit, and then receive, high frequency wavelength signals (e.g., electromagnetic waves) that travel through the formation surrounding the sensor. By comparing the transmitted and received signals, information can be determined concerning the nature of the formation through which the signal traveled, such as whether it contains water or hydrocarbons. Other sensors are used in conjunction with magnetic resonance imaging (MRI). Still other sensors include gamma scintillators, which are used to determine the natural radioactivity of the formation, and nuclear detectors, which are used to determine the porosity and density of the formation.
In traditional LWD and MWD systems, electrical power is supplied by a turbine driven by the mud flow. More recently, battery modules have been developed that are incorporated into the BHA to provide electrical power.
In both LWD and MWD systems, the information collected by the sensors must be transmitted to the surface, where it can be analyzed. Such data transmission is typically accomplished using a technique referred to as “mud pulse telemetry.” In a mud pulse telemetry system, signals from the sensor modules are typically received and processed in a microprocessor-based data encoder embodied in a collar as part of the BHA, which digitally encodes the sensor data. A controller in the control module then actuates a pulser, also incorporated into the BHA that generates pressure pulses within the flow of drilling mud that contains the encoded information. The pressure pulses are defined by a variety of characteristics, including amplitude (the difference between the maximum and minimum values of the pressure), duration (the time interval during which the pressure is increased), shape, and frequency (the number of pulses per unit time). Various encoding systems have been developed using one or more pressure pulse characteristics to represent binary data (i.e., bit 1 or 0)—for example, a pressure pulse of 0.5 second duration represents binary 1, while a pressure pulse of 1.0 second duration represents binary 0. The pressure pulses travel up the column of drilling mud flowing down to the drill bit, where they are sensed by a strain gauge-based pressure transducer. The data from the pressure transducer are then decoded and analyzed by the drilling rig operating personnel.
In the past, various patents have issued relating to the transmission of downhole conditions to a surface location. U.S. Pat. No. 3,867,714, issued on Feb. 18, 1975 to B. J. Patton, describes a logging-while-drilling (LWD) system, which is positioned within the drill string of a well drilling apparatus. The system includes a tool which has a turbine-like, signal-generating valve which rotates to generate a pressure wave signal in the drilling fluid which is representative of a measured downhole condition.
U.S. Pat. No. 4,520,468, issued on May 28, 1985 to S. A. Scherbatskoy, provides measurement-while-drilling (MWD) systems. The measurements are transmitted to the earth by a pulser, which produces common responses to electrical signals from a measuring instrument, and pressure pulses in the drilling fluid which are detected and decoded at the surface of the earth. The pulser is mounted in a special pulser sub which is of short length and enlarged internal diameter compared to the standard drill pipe and which is threadedly secured at each end to the drill string. An elongated housing is supported by the pulser sub. This elongated housing contains instrumentation or batteries and is connected to the pulser.
U.S. Pat. No. 4,562,560, issued on Dec. 31, 1985 to A. W. Kamp, provides a method and means for transmitting data through a drill string in a borehole. The data is in the form of pressure waves (such as pressure pulses) which are generated by means of a downhole mud motor that is driven by the drilling mud. The pressure waves are generated by varying the load on the mud motor according to a predetermined pattern that is representative of the data to be transmitted.
U.S. Pat. No. 5,679,894, issued on Oct. 21, 1997 to Kruger et al., describes a drilling system in which sensors are placed at selected locations in the drill string so as to continually measure various downhole operating parameters, including the differential pressure across the mud motor, rotational speed of the mud motor, torque, temperature, pressure differential between the fluid passing through the mud motor and the annulus between the drill string and the borehole, and the temperature of the circulating fluid. A downhole control circuit has a microprocessor so as to process signals from the sensors and transmit the process data uphole to a surface control unit by way of suitable telemetry.
U.S. Pat. No. 6,105,690, issued on Aug. 22, 2000 to Biglin, Jr. et al., provides a method and apparatus for communicating with a device downhole in a well, such as a sub in the BHA at the end of the drill string. Pressure pulses, such as those generated by the pistons of the mud pump, are transmitted through the drilling mud to a pressure pulsation sensor in the BHA. Based on its analysis of the pressure pulsations, the sensor can decipher a command from the surface so as to direct the steering of a steerable drill string.
U.S. Pat. No. 6,443,228, issued on Sep. 3, 2002 to Aronstam et al., is a method for utilizing flowable devices in wellbores. These flowable devices are used to provide communication between surface and the downhole instruments so as to establish a communication network in the wellbore. The flowable devices are adapted to move with a fluid flowing in the wellbore. The flowable device can be a memory device or a device that can provide a measurement of a parameter of interest. The flowable devices are introduced into the flow of a fluid flowing through a wellbore. The fluid moves the device in the wellbore. The flowable device is returned to the surface with the returning fluid.
U.S. Pat. No. 6,691,804, issued on Feb. 17, 2004 to W. H. Harrison, describes a directional borehole drilling system and method. Instrumentation located near the bit measures the present position when the bit is static and a dynamic tool face measures position when the bit is rotating. The data is processed to determine the error between present position and a desired trajectory.
U.S. Pat. No. 6,714,138, issued on Mar. 30, 2004 to Turner et al., discloses a method and apparatus for transmitting information to the surface from downhole in a well in which a pulser is incorporated into the BHA of a drill string, the pulser generating pressure coded pulses to contain information concerning the drilling operation. The pressure pulses travel to the surface where they are detected and decoded so as to decipher the information. The pulser includes a stator forming passages through which drilling fluid flows on its way to the drill bit. The rotor has blades that obstruct the flow of the drilling fluid through the passage when the rotor is rotated into a first orientation and when rotated into a second orientation, such that the oscillation of the rotor generates the encoded pressure pulses. An electric motor, under the operation of a controller, drives a drive train that oscillates the rotor between the first and second orientation. The controller controls one or more characteristics of the pressure pulses by varying the oscillation of the rotor. The controller may receive information concerning the characteristics of the pressure pulses from a pressure sensor mounted proximate to the BHA, as well as information concerning the angular orientation of the rotor by means of an encoder. The controller may also receive instructions for controlling the pressure pulse characteristics from the surface by means of encoded pressure pulses transmitted to the pulser from the surface that are sensed by the pressure sensor and decoded by the controller.
U.S. Pat. No. 6,898,150, issued on May 24, 2005 to Hahn, teaches a hydraulically balanced reciprocating pulser valve for mud pulse telemetry. Pressure fluctuations are generated by a reciprocating pulser system in a flowing drilling fluid. The system includes a reciprocating poppet and a stationary valve assembly with axial flow passages. The poppet reciprocates in close proximity to the valve assembly, at least partially blocking the flow through the valve assembly and generating oscillating pressure pulses. The poppet passes through two zero speed positions during each cycle, enabling rapid changes in signal phase, frequency, and/or amplitude thereby facilitating enhanced data encoding. The poppet is driven by a linear electric motor disposed in a lubricant filled housing.
Conventional downhole tools, MWD tools and steering tools typically will use a dedicated mud pulser (valve) that requires a large amount of power to actuate the valve and modulate the mud pressures in a manner that can be detected with a pressure transducer at the surface. These tools use mud pulsers or other means to generate oscillatory signals or mud pulses that create decreases and corresponding increases in the mud circulatory system. The significant proportion of the energy associated with conventional MWD pressure signals is the part of the signal waveform that increases the pressure of the system, whereas the part of the signal waveform that releases the system pressure uses a very small amount of energy. This invention capitalizes upon the energy savings associated with the pressure release encoded system that only releases pressures in the circulatory system as a transmission means. MWD tools are cost prohibitive as a means of transmitting the direction of the borehole when drilling vertical boreholes. Typically, periodic measurement of the “verticality of the well” is required by measuring the inclination of the borehole as the well is drilled deeper. Most vertically drilled wells use a cost-effective mechanical “drift indicator” that is lowered via a wireline into the well to make the inclination measurements at the required depth and pulled out of the hole to read the inclination. Mechanical drift tools are currently being replaced by newer electronic drift indicators. Thus, the industry has a need for a cost effective tool that can send inclination information to the surface without requiring the stopping of the drilling operation and the running of the wireline tool into the wellbore. A “real-time” tool that could replace wireline tools would have to be compact, relatively inexpensive, be robust and have a long operational life.
It is an object of the present invention to provide a cost effective system for communicating downhole directional information to the surface.
It is another object of the present invention to improve the existing use of the float valve (i.e. the reverse flow functionality) by imposing a pressure release encoding system.
It is another object of the present invention to provide a system and method that does not require significant modification of the drilling sub, which is already employed in the BHA.
It is a further object of the present invention to provide a pressure release encoding system and method, which minimizes the amount of power for the transmission of pressure information to the surface.
It is a further object of the present invention to provide a system and method whereby downhole conditions can be monitored in a relatively real-time manner at a surface location.
It is a further object of the present invention to make use of shock and movement sensors to allow the tool to automatically activate when in a borehole and automatically shut down when not needed, such that surface communication to the tool is not required prior to running the tool down hole.
It is a further object of the present invention to the extend battery life of the system by making use of the oil rig mud pumps as the primary energy source of the pressure release encoded system, thus enabling the system of the present invention to progressively release the pressure across the float valve in an energy efficient manner.
It is a further object of the present invention to use a hydraulic brake with a solenoid pilot valve as a control and a differential pressure sensor as a control feedback to accurately dictate the desired differential pressure drop across the float valve.
It is a further object of the present invention to use a pressure sensor within a hydraulic brake to detect the starting of the rig mud pumps.
It is a further object of the present invention to use a hydraulic brake, a single pressure sensor and solenoid pilot valve control to derive a desired differential pressure across the float valve.
It is a further object of the present invention to use a hydraulic brake, pressure sensor and solenoid pilot valve control to derive a predetermined differential pressure across the float valve independent of fluid density and fluid velocities.
It is a further object of the present invention to use a return spring within the hydraulic brake to close the main valve once the drilling interval has been completed and the mud pumps are turned off.
These and other objects and advantages of the present invention will become apparent from a reading of the attached specification and appended claims.